Find Energy Ltd.
TSX : FE

Find Energy Ltd.

March 22, 2006 16:05 ET

Find Energy Ltd. Announces 2005 Year End and Fourth Quarter Results

CALGARY, ALBERTA--(CCNMatthews - March 22, 2006) - Find Energy Ltd. ("Find" or the "Company") (TSX:FE) today announced its financial and operating results for the fourth quarter and twelve months ended December 31, 2005. This message should be read in conjunction with the audited financial statements and the Management's Discussion and Analysis, which form part of this press release. For additional information, these documents, along with other statutory filings, are available on SEDAR at www.sedar.com and the Company's website at www.findenergy.ca. Find's current presentation, which contains maps and a summary of the Company's activity in its principle operating areas, can also be found on the Company website.

Highlights of the fourth quarter and full year include:



2005 Highlights

Full Full % Change
Year Q4 Year 2005 vs
2005 2005 2004 2004
------------------------------------------------------------------------
Production Volumes:
Natural gas (mcf/d) 11,023 12,684 5,921 86
Oil & NGL (bbls/d) 1,409 1,256 1,351 4
------------------------------------------------------------------------
Total (boe/d) 3,246 3,370 2,338 39

Financial Results:
Revenue ($000) 63,463 19,948 34,681 83
Cash flow ($000) 37,589 12,162 16,098 134
per share ($) 1.12 0.36 0.56 100
Net income ($000) 11,963 4,736 2,905 312
per share ($) 0.36 0.14 0.10 260
Cash flow netback - per boe ($) 31.72 39.23 18.81 69
Operating expenses - per boe ($) 7.77 7.88 9.78 (21)
General and administrative - per
boe ($) 0.80 0.53 1.96 (59)
Capital expenditures, before
dispositions ($000) 96,110 42,284 45,758 110
Dispositions ($000) 28,346 - 4,350 652
Net capital expenditures ($000) 67,764 42,284 41,408 64
Bank debt plus working capital
deficiency ($000) 43,556 43,556 17,656 147
Basic shares outstanding (000) 34,026 34,026 33,542 1


Natural
Reserve Volumes: (1) Oil Gas NGL Total
(total Company interest) (mbbls) (mmcf) (mbbls) (mboe)
------------------------------------------------------------------------
Total proved 1,487 42,972 1,662 10,311
Probable 523 12,323 443 3,020
------------------------------------------------------------------------
Total proved plus probable 2,010 55,295 2,105 13,331


Summary of Net Present Values of Future Net Revenue ($000) (1)
(forecast prices and costs)

Net Present Values Before Income Taxes
Discounted at
------------------------------------------------------------------------
0% 5% 10%
------------------------------------------------------------------------
Total proved 354,225 282,326 240,621
Probable 101,579 58,041 39,752
------------------------------------------------------------------------
Total 455,804 340,367 280,373

(1) Based on a report prepared by GLJ Petroleum Consultants Ltd. ("GLJ")
dated January 1, 2006.


Production Growth

Find's natural gas production increased by nine percent or 1.1 mmcf per day in the fourth quarter compared to the third quarter. Almost all of this new gas production came from the Pembina West area. On December 29, 2005 the Pembina Blue Rapids gas plant began commercial production and most of the Company's previously shut-in gas wells began producing.

Crude oil and natural gas liquids production grew by 12 percent to 1,256 barrels per day in the fourth quarter compared to the third. As with gas, most of this increase was due to successful wells at Pembina West.

Full year 2005 production was 39 percent higher in 2005 than in 2004. Gas production grew by 86 percent to 11.0 mmcf per day compared to 5.9 mmcf per day averaged in the full year of 2004.

Oil production in 2005 compared to 2004 was up four percent to 1,409 barrels per day, despite the Company selling its Southeast Saskatchewan production in June 2005.

At the time of writing this year-end report, Find estimates that it is producing 5,500 boe per day comprised of 24.7 mmcf per day and 1,400 barrels per day of oil and NGL.

Reserve Gains

Proved plus probable reserves increased by 56 percent to 13.3 million boe versus 8.5 million boe at year-end 2004.

Find had an excellent year in terms of replacing reserves as 8.6 million boe of reserves were added via the drill-bit versus production of 1.2 million boe. This equates to a reserve replacement ratio of 7.3 times production. After dispositions of 2.1 million proved boe and 2.8 million proved plus probable boe of reserves, mostly from Southeast Saskatchewan, and positive technical revisions of 0.2 million proved plus probable boe, a net total of 5.9 million boe were added, resulting in a reserve replacement ratio of 5.0 times production net of dispositions.

Finding and Development Costs

Find's 2005 finding and development costs were $13.81 per boe including future capital on a proved basis and $11.51 per boe on a proved plus probable basis. Find's two-year weighted average finding and development costs are $15.01 per boe for proved and $12.30 per boe for proved plus probable reserves.

Reserve Life Index

Based on fourth quarter 2005 average production volumes, Find's reserve life index is 8.4 years on a proved basis and 10.8 years on a proved plus probable basis. Find's reserve life index at year-end 2004, based on GLJ's reserves, was 6.8 years for proved and 9.1 years for proved plus probable reserves.

Net Asset Value

Based on the GLJ report and an independent estimate of the Company's land valued at $19.1 million, provided by Seaton Jordan and Associates Ltd., Find has a net asset value at year-end 2005 of $7.52 per share. This is based on proved plus probable reserves, a forecast of future prices dated January 1, 2006 and a discount rate of 10 percent. At year-end 2004, Find's net asset value, based on similar parameters, was $2.99 per share. This represents a year-over-year increase in net asset value per share of 152 percent.

Financial Results

Net Income and Cash Flow

In 2005, Find generated revenue from the sale of its crude oil and natural gas of $63.5 million. This produced cash flow from operations of $37.6 million, or $1.12 per share and net income of $12.0 million or $0.36 per share.

Product Pricing

In 2005, Find received an average price of $9.33 per mcf for its natural gas. The average price Find received for its oil and natural gas liquids during the year was $51.01 per barrel, after adjusting for a $0.32 per barrel loss on hedging. This compares to net prices (after hedging) in 2004 of $6.89 per mcf for natural gas and $40.03 per barrel for oil and natural gas liquids.

Operating Costs

Find made progress in lowering its operating costs in 2005, reflecting production increases from a number of properties, and efficiencies gained in field operations. Operating costs for 2005 were $7.77 per boe, a 21 percent decrease from $9.78 in 2004. Find expects operating costs will decline further in 2006 based on production increases at Pembina West, most of which will be processed at Find's 85-percent owned and operated Pembina Blue Rapids gas plant.

Cash Flow Netback

Find realized a cash flow netback of $31.72 per boe in 2005. The cash flow netback includes deductions for royalties, operating costs, general and administrative expenses, interest expenses and capital taxes. During the fourth quarter of 2005 Find realized a cash flow netback of $39.23 per boe.

Working Capital and Bank Debt

At December 31, 2005, Find had bank debt of $25.3 million and a working capital deficiency of $18.3 million for total debt of $43.6 million. This equates to 0.9 times the Q4 2005 cash flow expressed as an annualized amount of $48.7 million. Total debt at the end of 2004 was $17.7 million comprised of $9.2 million of bank debt and $8.5 million of working capital deficiency.

Since the end of the year, the Company has negotiated a new revolving demand loan in the amount of $100 million.

Drilling

During 2005, Find drilled 63 (43.6 net) wells, resulting in 57 (39.8 net) natural gas wells, 3 (1.8 net) oil wells and 3 (2.0 net) dry holes. Find operated the drilling of 59 of these wells or 94 percent. Find had a 95 percent drilling success rate in 2005 on a gross and net well basis.

Focus Area Review

Pembina West, Alberta

In 2005, Find operated the drilling of 39 (28.5 net) wells at Pembina West. Find owns a major working interest and is the operator of 52 sections of land in the Pembina West area. The Company currently produces oil, natural gas and natural gas liquids from seven different pay zones. To date, Find has drilled a total of 60 (42.7 net) wells at Pembina. Of the total, 56 (39.7 net) are either on production or being prepared for production while 4 (3.0 net) have been suspended because they have not tested at commercial rates.

In late December 2005, Find commenced operating its 85-percent owned and operated Pembina Blue Rapids gas plant. The gas plant is currently working at full capacity. Based on established gas supply, Find expects the plant will continue to operate at capacity through the remainder of 2006. Approximately 65 percent of the gas plant throughput is owned by Find, while the remainder is owned by other operators who pay a processing fee to Find.

Current production from the Pembina West area is approximately 4,000 boe per day net to Find, compared to 275 boe per day at year-end 2004.

Since the beginning of 2006, Find has drilled 11 (8.3 net) wells at Pembina, resulting in 11 (8.3 net) gas wells. All of these wells have now been completed and production tested. Results vary, but one of the wells (0.60 net), producing from the Rock Creek formation, was production tested at 6.5 mmcf per day. Another well (1.0 net) tested the Nordegg formation at 4.5 mmcf per day, while another (0.50 net) tested the Notikewan formation at 4.2 mmcf per day. Work is presently underway to bring these wells on production later in 2006. Although these initial rates are encouraging, there is always some uncertainty associated with the rate at which these wells may commence production and decline thereafter.

Find currently plans to drill a total of 43 (34 net) wells in the Pembina area during 2006.

Bigstone, Alberta

During 2005, Find drilled 3 (1.2 net) wells in the Bigstone area resulting in 1 (0.3 net) gas well and 2 (1.0 net) dry holes. Since the beginning of the year, 1 (0.76 net) well was drilled at Bigstone resulting in a well which tested gas in the Cadomin formation at a rate of 2.2 mmcf per day. Plans are underway for this well to commence production within the next three months.

Aerial, Alberta

In the fourth quarter, Find drilled 6 (4.6 net) wells at Aerial resulting in 6 (4.6 net) gas wells. The wells have since been completed and will add combined production of approximately 1.5 mmcf per day. The wells are scheduled to commence production within the next thirty days.

Outlook

Find's 2006 capital budget currently provides for expenditures of approximately $70 million. Activities will include the drilling of 71 (56 net) wells along with other production and exploration-related costs. Approximately 65 percent of the capital budget, or $45 million, has been allocated to Pembina, Alberta.

Since the beginning of the year, the Company has participated in drilling 15 (9.8 net) wells, resulting in 12 (9.0 net) gas wells, 1 (0.3 net) oil well and 2 (0.5 net) dry holes. Approximately $30 million has been invested so far in 2006.

Find is committed to grassroots, full-cycle exploration and is continuing to develop new prospecting ideas and areas.

This news release contains information regarding estimated net present values of reserves. It should not be assumed that the estimates of net present value of the reserves represents the fair market value of the reserves.

Investors are further cautioned that the preparation of financial statements in accordance with Canadian generally accepted accounting principles ("GAAP") requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Estimating reserves is also critical to several accounting estimates and requires judgments and decisions based upon available geological, geophysical, engineering and economic data. These estimates may change, having either a negative or positive effect on net earnings as further information becomes available, and as the economic environment changes.

Under NI 51-101, the methodology used to calculate FD&A costs includes incorporating changes and future development capital ("FDC") required to bring proved undeveloped and probable reserves to production. For continuity, Find presented FD&A costs both excluding and including FDC.

In all cases, the FD&A number is calculated by dividing the identified capital expenditures by the applicable reserve additions. Find has adopted the standard of 6 mcf of natural gas being equivalent to 1 barrel of oil when converting natural gas to barrels of oil equivalent (boe). This practice may be misleading, particularly if used in isolation. A 6:1 conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

This news release contains certain forward-looking statements, which are based on Find's current internal expectations, estimates, projections, assumptions and beliefs. Some of the forward-looking statements may be identified by words such as "expects", "anticipates", "believes", "projects", "plans" and similar expressions. These statements are not guarantees of future performance and involve a number of risks and uncertainties, many of which are beyond Find's control. Such forward-looking statements necessarily involve known and unknown risks and uncertainties, which may cause Find's actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements and, accordingly, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do, what benefits Find will derive from them. The risks and uncertainties associated with the forward-looking statements included in this news release include, among other things, changes in general economic, market and business conditions; changes or fluctuations in production levels, unexpected drilling results, commodity prices, currency exchange rates, capital expenditures, reserves or reserves estimates and debt service requirements; changes to legislation, investment eligibility or investment criteria; Find's ability to comply with current and future environmental or other laws; Find's success at acquisition, exploration and development of reserves; actions by governmental or regulatory authorities including increasing taxes, changes in investment or other regulations; and the occurrence of unexpected events involved in the exploration for, and the operation and development of, oil and gas properties. Many of these risks and uncertainties are described in Find's Annual Information Form and Find's Management's Discussion and Analysis. Readers are also referred to risk factors described in other documents Find files with Canadian securities authorities. Copies of these documents are available without charge from Find. Except as required by applicable law, Find disclaims any responsibility to update these forward-looking statements.

FIND ENERGY LTD.

MANAGEMENT'S DISCUSSION AND ANALYSIS

This management's discussion and analysis ("MD&A") dated March 22, 2006, should be read in conjunction with the annual audited financial statements of Find Energy Ltd. ("Find" or the "Company") as well as the Annual Information Form and the Statement of Reserves Data and Other Information. These documents along with other statutory filings are available on SEDAR at www.sedar.com and at the Company's website at www.findenergy.ca.

In this MD&A, the calculation of boe is based on the conversion rate of six thousand cubic feet of natural gas for one barrel of oil. This conversion conforms to National Instrument 51-101 - Standards for Oil and Gas Activities of the Canadian Securities Administrators. Readers are cautioned that boe may be misleading if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

This MD&A contains forward-looking statements. Forward-looking statements are based on current expectations that involve a number of risks and uncertainties which could cause actual events or results to differ materially from those reflected in the MD&A. Forward-looking statements are based on the estimates and opinions of Find's management at the time the statements were made.

The MD&A contains the term cash flow from operations, which should not be considered an alternative to, or more meaningful than, cash flow from operating activities as determined in accordance with Canadian generally accepted accounting principles as an indicator of the Company's performance. Find's calculation of cash flow from operations may not be comparable to that reported by other companies. Cash flow from operations per share is calculated using the same weighted average number of shares outstanding used in the calculation of income per share.

The term "2005" refers to the 12 months ended December 31, 2005 and "Q4" and "Q3" refers to the three months ended December 31, 2005 and September 30, 2005 respectively. The terms "Q2" and "Q1" refer to the three months ended June 30, 2005 and March 31, 2005 respectively. The term "2004" refers to the 12 months ended December 31, 2004.



Volumes
2005 Q4 Q3 2004
----------- --------- ---------- ---------
Natural gas (mcf/day) 11,023 12,684 11,588 5,921
Oil and NGL (bbls/day) 1,409 1,256 1,122 1,351
----------- --------- ---------- ---------
Total (boe/day) 3,246 3,370 3,053 2,338
----------- --------- ---------- ---------
----------- --------- ---------- ---------


Find's gas production increased by nine percent or 1.1 mmcfd in the fourth quarter as compared to the third quarter. Almost all of this new gas production came from the Pembina West area. On December 29, 2005, the Pembina Blue Rapids Gas Plant began commercial production and most of the Company's previously shut-in gas wells began producing.

Crude oil and natural gas liquids production grew by 12 percent to 1,256 bopd in the fourth quarter as compared to the third. As with gas, most of this increase was due to successful wells at Pembina West.

Natural gas liquids production grew due to gas volume increases, but Find also had success in developing new oil pools in the Pembina West area.

Full year production was 3,246 boed or 39 percent higher than the full year production for 2004. During 2005, Find sold all of its remaining Southeast Saskatchewan oil properties. These properties contributed a total of 295 boed to 2005 daily average production and 602 boed to 2004 daily average production.



Daily Production by Area
Twelve Months Ended December 31, 2005

Natural
Crude Oil Gas NGL Total
Area (bbls/day) (mcf/day) (bbls/day) (boe/day)
----------- --------- ---------- ---------

Pembina West 90 5,148 320 1,268
Aerial 74 1,871 29 415
Hazlet 356 - - 356
Kaybob - 1,102 32 216
Neutral Hills 124 490 1 206
Edenvale/Redvers (1) 108 46 3 118
Ingoldsby (1) 96 - - 96
Others 128 2,366 48 571
----------- --------- ---------- ---------
Total 976 11,023 433 3,246
----------- --------- ---------- ---------
----------- --------- ---------- ---------
(1) Sold in disposition of Southeast Saskatchewan properties in June
2005

Product Pricing
Natural Gas ($/mcf) 2005 Q4 Q3 2004
----------- --------- ---------- ---------
Price before hedging 9.33 11.91 9.60 6.87
Hedging gain - - - 0.02
----------- --------- ---------- ---------
Net price 9.33 11.91 9.60 6.89
----------- --------- ---------- ---------
----------- --------- ---------- ---------
AECO daily index 8.71 11.31 9.30 6.53
NYMEX (US$/mcf) 9.00 12.86 9.72 6.20


Find's realized natural gas price increased by $2.31 per mcf in the fourth quarter, an increase of 24 percent over the $9.60 per mcf received in the third quarter. Prices at the AECO storage hub and on the NYMEX market followed suit, increasing by 22 percent and 32 percent respectively.

The traditional winter heating season began with storage facilities completely full in the U.S. Early cold snaps in late November and early December caused prices to race upwards and lifted fourth quarter average prices well above the third quarter. However, unseasonably warm weather from mid-December on has reduced heating demand for natural gas and consequently lowered gas prices.

Find had no natural gas price hedges in place during 2005 and has not entered into any subsequent to year-end.



Oil and Natural Gas Liquids
($/bbl) 2005 Q4 Q3 2004
----------- --------- ---------- ---------
Price before hedging 51.33 52.33 58.25 43.41
Hedging loss (0.32) - - (3.38)
----------- --------- ---------- ---------
Net price 51.01 52.33 58.25 40.03
----------- --------- ---------- ---------
----------- --------- ---------- ---------
WTI (US$/bbl) 56.45 60.03 63.01 41.42
Edmonton Light ($/bbl) 69.28 71.64 77.21 52.91
CDN$/US$ 0.826 0.8526 0.8325 0.7698


Find's fourth quarter realized oil and natural gas liquids price was $52.33 per bbl, a decrease of 10 percent from the $58.25 per bbl received in the third quarter. WTI was down five percent in the quarter and Edmonton Light was off seven percent. A strengthening CDN$ (up 2.4 percent) in the quarter reduced the value of Edmonton Light postings. The differential for Find's medium gravity oil production was $6.53 per bbl greater in the fourth quarter when compared to the third, further reducing the corporate oil price.

For the full year of 2005 crude oil averaged an all time record high of $56.45 per bbl, fully 36 percent higher than the 2004 average price. Strong demand growth in Asian economies caused the world's excess supply capacity to dwindle to near zero. Political instability in key oil producing regions of the world as well as damage to Gulf of Mexico producing platforms from Hurricane Katrina added an element of nervousness to oil prices. The current forward curve for WTI in 2006 is above average price levels for 2005.



Income Statement

Revenue 2005 Q4 Q3 2004
----------- --------- ---------- ---------
Oil and natural
gas sales ($000) 63,931 19,948 16,248 36,353
Per boe ($) 53.95 64.34 57.84 42.48
Hedging loss ($000) 468 - - 1,672
Per boe ($) 0.39 - - 1.95

The following table reconciles oil and natural gas revenue between the
third and fourth quarter of 2005:

Revenue for the three months ended September 30, 2005 ($000) 16,248
Increase in commodity prices ($000) 1,857
Increase in production volumes ($000) 1,843
---------
Revenue for the three months ended December 31, 2005 ($000) 19,948
---------
---------

The following table reconciles oil and natural gas revenue between the
twelve months ended December 31, 2005 and December 31, 2004.

Revenue for the 12 months ended December 31, 2004 ($000) 36,353
Increase in commodity prices ($000) 9,303
Increase in production volumes ($000) 18,275
---------
Revenue for the 12 months ended December 31, 2005 ($000) 63,931
---------
---------

Royalties 2005 Q4 Q3 2004
----------- --------- ---------- ---------
Total royalties ($000) 15,159 4,972 3,909 7,772
% of revenue before hedging 23.7% 24.9% 24.1% 21.4%
Per boe ($) 12.79 16.03 13.92 9.08


Royalty rates moved higher in the fourth quarter, increasing to 24.9 percent. Part of this increase is due to higher gas prices received during the quarter; however, the impact of Pembina West production and its "new gas" status also increased the rate.



Operating Expenses 2005 Q4 Q3 2004
----------- --------- ---------- ---------
Total lease operating
($000) 9,202 2,444 1,954 8,368
Per boe ($) 7.77 7.88 6.95 9.78


Lease operating costs were up 13 percent on a boe basis in the quarter to $7.88 from $6.95 in the third quarter. During the quarter, the Company commenced production from a number of oil wells in the Pembina West area. These wells are producing as single well batteries and consequently have higher operating costs than the Company's gas wells. Find also incurred some one time repair costs to its Aerial and Hazlet properties.

For the full year of 2005, Find reduced its lease operating costs by $2.01 per boe or 21 percent when compared to full year 2004 costs. This reduction is reflective of the Company's strategy of focusing on operated natural gas opportunities and the subsequent disposition of all of its Southeast Saskatchewan oil production.



General & Administrative
($000) 2005 Q4 Q3 2004
----------- --------- ---------- ---------
Total G & A expense 5,221 1,817 1,058 4,082
Recoveries (2,346) (1,017) (541) (1,208)
Capitalized (1,923) (636) (384) (1,198)
----------- --------- ---------- ---------
Net 952 164 133 1,676
----------- --------- ---------- ---------
----------- --------- ---------- ---------
Per boe ($) 0.80 0.53 0.47 1.96


Net general and administrative costs increased slightly to $0.53 per boe in the fourth quarter from $0.47 in the third. Gross general and administrative costs grew to $1.8 million in the quarter, primarily as a result of year-end bonus payments. These were offset by record overhead recoveries totalling $1 million. These recoveries were driven by the most active quarter in the Company's history, in which Find spent $41.7 million in field activities drilling, completing, equipping and tying-in 26 wells as well as building the Pembina West gas plant.

Full year net general and administrative costs fell by 59 percent to $0.80 per boe compared to $1.96 per boe in 2004. During the year, Find's employee count grew by five to total 29. This staffing level can comfortably sustain operations at the Company's current production level.



Interest Expense ($000) 2005 Q4 Q3 2004
----------- --------- ---------- ---------
Total interest expense
($000) 418 65 21 642
Per boe ($) 0.35 0.21 0.08 0.75


Loan interest grew in the fourth quarter as the Company's average loan balance increased when compared to the third quarter. The prime lending rate also increased from 4.5 percent at the end of the third quarter to 5.0 percent by the end of quarter four.



Provision for Taxes ($000) 2005 Q4 Q3 2004
----------- --------- ---------- ---------
Future income taxes 7,885 2,930 2,228 1,559
Current tax expense 32 32 - -
Capital tax expense 516 109 76 576
----------- --------- ---------- ---------
Total tax expense 8,433 3,071 2,304 2,135
----------- --------- ---------- ---------
----------- --------- ---------- ---------


Find had no cash income tax expense in 2005, due to its large opening tax pool balance and the level of capital expenditures undertaken during the year.

Capital tax expense, which consists of Federal Large Corporations Tax and Saskatchewan Resource Surcharge, increased to $109,000 in the fourth quarter from $76,000 in the third. This was due to Find's record fourth quarter capital expenditures program.

Current tax expense of $32,000 is due to a federal tax reassessment of the 2002 taxation year.



Stock-based Compensation
($000) 2005 Q4 Q3 2004
----------- --------- ---------- ---------
Total stock-based
compensation 1,535 406 395 1,118
Capitalized (561) (138) (138) (365)
----------- --------- ---------- ---------
Net 974 268 257 753
----------- --------- ---------- ---------
----------- --------- ---------- ---------
Per boe ($) 0.82 0.86 0.92 0.88


Stock-based compensation is a non-cash calculation that attempts to value stock options at the time they are granted. As the Company had very little change in outstanding options in the fourth quarter, there was only a slight change in the expensed amount.



Depletion, Depreciation
and Accretion 2005 Q4 Q3 2004
----------- --------- ---------- ---------
Total DD&A ($000) 16,396 4,229 3,981 11,254
Per boe ($) 13.84 13.64 14.17 13.15


Depletion, depreciation and accretion fell by four percent in the fourth quarter to $13.64 per boe. This is due to the Company's excellent proven reserve additions in the fourth quarter from its drilling program. During the fourth quarter, Find completed the construction of the Pembina West Gas Plant. The costs of the plant totaled $9.9 million, all of which were depreciated over the entire fourth quarter results. Had these costs been excluded, the fourth quarter depletion, depreciation and accretion rate would have been $12.69 per boe.



Net Income ($000) 2005 Q4 Q3 2004
----------- --------- ---------- ---------
Net income 11,963 4,736 3,717 2,905
Per boe ($) 10.10 15.27 13.23 3.39
Per share ($) 0.36 0.14 0.11 0.10
Diluted per share ($) 0.34 0.13 0.11 0.10
Weighted average shares
outstanding (000) 33,627 33,910 33,498 28,531


Net income in the fourth quarter grew by 27 percent to $4.7 million over the third quarter. This increase was caused mostly by improved commodity prices, which were up by 11 percent quarter over quarter. Cash costs offset the price improvement somewhat, increasing by 17 percent over the third quarter.

Full year net income was up 312 percent to $12.0 million when compared to 2004 full year income. On a boe basis, the increase was 198 percent. All facets of Find's business influenced this improvement, including increased production volumes, increased commodity prices and decreased cash costs.



2005 Q4 Q3
-------------- ------------- --------------
$000 $/boe $000 $/boe $000 $/boe
-------------- ------------- --------------

Revenue, net of hedging 63,868 53.90 19,948 64.34 16,276 57.94
-------------- ------------- --------------

Royalties 15,159 12.79 4,972 16.03 3,909 13.92
Operating expenses 9,202 7.77 2,444 7.88 1,954 6.95
General and administrative 952 0.80 164 0.53 133 0.47
Interest 418 0.36 65 0.21 21 0.08
Capital taxes 548 0.46 141 0.46 76 0.27
-------------- ------------- --------------
26,279 22.18 7,786 25.11 6,093 21.69
-------------- ------------- --------------
-------------- ------------- --------------

Cash flow from operations 37,589 31.72 12,162 39.23 10,183 36.25

Depletion, depreciation
and accretion 16,396 13.84 4,229 13.64 3,981 14.17
Stock-based compensation 974 0.82 268 0.86 257 0.92
Unrealized gain on
financial instrument 371 0.31 - - - -
Future taxes 7,885 6.65 2,930 9.46 2,228 7.93
-------------- ------------- --------------
Net income 11,963 10.10 4,736 15.27 3,717 13.23
-------------- ------------- --------------
-------------- ------------- --------------


Liquidity and Capital Resources

Cash Flow from Operations 2005 Q4 Q3 2004
----------- --------- ---------- ---------
Cash flow from operations
($000) 37,589 12,162 10,183 16,098
Cash flow from operations,
per basic share ($) 1.12 0.36 0.30 0.56
Cash flow from operations,
per diluted share ($) 1.07 0.34 0.29 0.56
Cash flow netback, per
boe ($) 31.72 39.23 36.25 18.81
Cash flow as a percentage
of revenue 58.8% 61.0% 62.6% 44.3%
Weighted average basic
shares outstanding (000) 33,627 33,910 33,498 28,531


Cash flow from operations in the fourth quarter was 19 percent higher than in the third, totalling $12.2 million or $0.36 per basic share. Full year cash flow was up by 134 percent or 100 percent on a per share basis. Major contributors to this increase were production volumes (up 39 percent), commodity prices (up 27 percent) and cash costs (down 29 percent).



Capital Expenditures ($000) Q4 Q3 Q2 Q1
----------- --------- ---------- ---------
Land and seismic 895 4,036 (27,867) 820
Drilling and completions 23,307 15,821 6,107 11,742
Well equipment and
facilities 7,594 3,461 1,258 5,301
Pembina Blue Rapids
gas plant 9,851 3,515 - -
----------- --------- ---------- ---------
41,647 26,833 (20,502) 17,863
Capitalized G & A 636 384 580 322
----------- --------- ---------- ---------
Total capital expenditures 42,283 27,217 (19,922) 18,185
----------- --------- ---------- ---------
----------- --------- ---------- ---------


Find had the most active year in its history, investing a total of $96.2 million drilling, completing, equipping and tying-in a total of 63 wells, as well as constructing the Pembina Blue Rapids gas plant. Funding for this program came from a variety of sources:



$ Million
-----------

Cash flow from operations 37.6
Sale of Southeast Saskatchewan assets 28.3
Draw on bank line of credit 16.1
Decrease in current assets 9.4
Issue of shares, net of costs 8.4
Repurchase of shares (3.6)
-----------

Total of capital investments 96.2
-----------
-----------


Capital Expenditures by Area
(Twelve Months ended December 31, 2005)

Land/ Drill/ Equip/
Area ($000) Seismic Comp. Facilities Total
----------- --------- ---------- ---------

West Central 5,625 53,138 28,949 87,712
East Central (13) 3,531 800 4,318
Southeast Saskatchewan (28,361) 126 276 (27,959)
Other 633 182 955 1,770
----------- --------- ---------- ---------
(22,116) 56,977 30,980 65,841
----------- --------- ---------- ---------
----------- --------- ---------- ---------


Accounts Receivable

At December 31, 2005, Find had $16.7 million of accounts receivable in current assets. Of this amount, $6.9 million represents an accrual for revenue, all of which was collected by the end of January. An additional $2.8 million is due from governments for ARTC and GST refunds. The remaining balance is due from Find's joint venture partners. Find manages these relationships carefully, utilizing the provisions of existing joint venture agreements to ensure that these receivables are collected in a timely manner. At this time, the Company does not believe any of these amounts to be uncollectible.

Equity Financing

On August 18, 2005, the Company closed a bought-deal private placement of flow-through common shares. A total of 1,000,000 shares were sold at an issue price of $7.60 per share. Net proceeds from the issue were approximately $7.1 million. Find used the proceeds to fund seismic programs and exploration drilling, primarily in the Pembina West area. As of December 31, 2005, all of the exploration expenditures had been incurred.

Normal Course Issuer Bid

On May 31, 2005, Find filed a Notice of Intention to make a normal course issuer bid through the Toronto Stock Exchange. Find intends to use the bid to purchase and cancel shares at prices that are not reflective of the current fair value of Find shares relative to its assets, opportunity base and competitors' valuations. The Company intends to finance the issuer bid through cash flow and bank lines of credit.

During the year, Find purchased 710,400 shares at an average cost including commission of $5.10 per share.

Note Receivable

In late 2004, Find sold minor Saskatchewan properties. Proceeds received included a non-interest bearing promissory note. The note was to be repaid in equal monthly installments over a period of one year. The final payment on the note was received during the third quarter.



Wells Drilled by Area
(Twelve Months ended December 31, 2005)

Gas Oil D & A Total
----------- ---------- ---------- ----------- Success
Area Gross Net Gross Net Gross Net Gross Net Rate
----------- ---------- ---------- ----------- --------

West Central 51.0 35.2 3.0 1.8 3.0 2.0 57.0 39.0 95%
East Central 6.0 4.6 - - - - 6.0 4.6 100%
----------- ---------- ---------- ----------- --------
57.0 39.8 3.0 1.8 3.0 2.0 63.0 43.6 95%
----------- ---------- ---------- ----------- --------
----------- ---------- ---------- ----------- --------


The fourth quarter was the most active in the Company's history. Find drilled a total of 26 gas wells (18.4 net). Of the 26 gas wells drilled in the quarter, 17 (12.5 net) were drilled at Pembina West, 5 (3.7 net) were drilled at Aerial, 3 (2.0 net) were drilled at Whitecourt and 1 (0.2 net) at Alder Flats.

Reserves

The reserves data set forth below is based upon an evaluation by GLJ Petroleum Consultants Ltd. ("GLJ"), independent reserves evaluator, with an effective date of December 31, 2005. The reserves data summarizes the oil, liquids and natural gas reserves of Find and the net present value of future net revenues for these reserves using forecast prices and costs. The forecast prices and costs used are summarized below.

This reserves data conforms to the requirements of National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities "NI-5101". Additional information not required by NI-5101 has been presented to provide continuity and additional information which Find believes is important to the readers of this information. The Company engaged GLJ to provide an evaluation of proved and proved plus probable reserves and no attempt was made to evaluate possible reserves. All of Find's reserves are in Alberta and Saskatchewan, Canada.

It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and costs and cost assumptions will be attained, and variances could be material. The recovery and reserve estimates of the Company's crude oil, natural gas liquids and natural gas reserves provided below are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided.



Summary of Company Interest Oil & Natural Gas Reserves
(forecast prices and costs)
As at December 31, 2005

Natural Gas
Crude Oil Natural Gas Liquids Total
(Mbbl) (Mmcf) (Mbbl) (Mboe)
-------------- --------------- ------------- ---------------
TCI(1) Net(2) TCI(1) Net(2) TCI(1) Net(2) TCI(1) Net(2)
-------------- --------------- ------------- ---------------
Proved
Developed
producing 1,291 1,099 33,487 25,945 1,355 922 8,227 6,345
Developed
non
-producing 72 70 9,318 7,245 302 202 1,927 1,480
Undeveloped 124 119 167 122 5 3 157 142
-------------- --------------- ------------- ---------------
Total
proved 1,487 1,288 42,972 33,312 1,662 1,127 10,311 7,967
Probable 523 470 12,323 9,885 443 301 3,020 2,419
-------------- --------------- ------------- ---------------
Total
proved
plus
probable 2,010 1,758 55,295 43,197 2,105 1,428 13,331 10,386
-------------- --------------- ------------- ---------------
-------------- --------------- ------------- ---------------

(1) Total Company Interest; includes working interest and royalty
interest reserves
(2) Net reserves are total Company interest reserves, net of royalties


Proved developed non-producing reserves are reserves on wells that had been drilled by December 31 and have been subsequently completed and classified as proved, but were not producing as of the effective date of the engineering report. These wells require minor capital expenditures to bring them on production. Find had a total of 1,927,000 boe of reserves classified as proved developed non-producing. By the end of the first quarter of 2006, the Company expects to have brought on production proved developed non-producing reserves having in aggregate a total of 1,476,000 boe, thereby transferring them to proved producing.



Summary of Net Present Values of Future Net Revenue ($000)
(forecast prices and costs)
As at December 31, 2005

Net Present Values Before Income Taxes
Discounted at
--------- --------- ---------
0% 5% 10%
--------- --------- ---------
Proved
Developed producing 293,308 231,218 196,252
Developed non-producing 58,793 49,690 43,454
Undeveloped 2,124 1,418 915
--------- --------- ---------
Total proved 354,225 282,326 240,621
Probable 101,579 58,041 39,752
--------- --------- ---------
Total 455,804 340,367 280,373
--------- --------- ---------
--------- --------- ---------


GLJ Petroleum Consultants Ltd.
Forecast Price File
Effective January 1, 2006

Edmonton Henry Hub
WTI Light Gas AECO - C Spot
CDN$ US$ CDN$ US $/mmbtu CDN $/mmbtu
------ ------- ---------- ------------ ---------------

2006 0.85 57.00 66.25 10.50 10.60
2007 0.85 55.00 64.00 8.75 9.25
2008 0.85 51.00 59.25 7.50 8.00
2009 0.85 48.00 55.75 7.00 7.50
2010 0.85 46.50 54.00 6.75 7.20
2011 0.85 45.00 52.25 6.50 6.90
2012 0.85 45.00 52.25 6.50 6.90
2013 0.85 46.00 53.25 6.65 7.05
2014 0.85 46.75 54.25 6.75 7.20
2015 0.85 47.75 55.50 6.90 7.40
2016+ 0.85 48.75 56.50 7.05 7.55


Reserves by Major Property
As at December 31, 2005

Proved plus Probable
Proved Proved Discount Rate @
Area Developed Total plus ---------------------
(Mboe) Producing Proved Probable 8% 10%
--------- --------- --------- ---------------------
($000) ($000)
---------------------
Pembina West 5,126 6,619 8,459 205,111 191,147
Aerial 619 816 1,081 24,812 23,548
Kaybob 529 663 900 16,874 15,466
Hazlet 667 667 848 9,475 8,854
Bigstone 401 409 505 9,853 9,127
Others 885 1,137 1,538 34,577 32,232
--------- --------- --------- ---------------------
8,227 10,311 13,331 300,702 280,374
--------- --------- --------- ---------------------
--------- --------- --------- ---------------------


The following table reconciles changes to Find's reserves as at December 31, 2004 to Find's reserves at December 31, 2005 through drilling additions, dispositions and production.



Total Company Interest Reserve Reconciliation

Total Proved
Total Proved plus Probable
------------------------ -----------------------
Natural Oil & Natural Oil &
Gas NGL Total Gas NGL Total
(Mmcf) (Mbbls) (Mboe) (Mmcf)(Mbbls) (Mboe)
------------------------ -----------------------

December 31, 2004 16,164 3,658 6,353 22,280 4,773 8,487
Additions, through
drilling and
acquisitions 30,542 1,695 6,785 38,475 2,218 8,630
Revisions 921 381 535 (635) 355 249
Dispositions (632) (2,071) (2,176) (802)(2,717)(2,851)
Production (4,023) (514) (1,185) (4,023) (514)(1,185)
------------------------ -----------------------
December 31, 2005 42,972 3,149 10,312 55,295 4,115 13,330
------------------------ -----------------------
------------------------ -----------------------


Find had an excellent year in terms of replacing reserves as 8.6 million boe of reserves were added via the drill bit versus production of 1,185,000 boe. This equates to a reserve replacement ratio of 7.3 times production.

In June of 2005, Find closed the disposition of the remainder of its Southeast Saskatchewan properties. A total of 2.2 million proved boes and 2.9 million proved plus probable boes were sold for total proceeds after adjustments of $28.3 million. At the time of closing, these properties were producing 580 boed.

The properties in Southeast Saskatchewan were characterized by high operating costs and few opportunities for growth. The disposition provided Find with additional capital to intensify its drilling program in higher-return operated areas, primarily at Pembina West.



Reserves per share (000) December 31, 2005 December 31, 2004
----------------- ------------------

Proven reserves 10,311 6,353
Proven plus probable reserves 13,331 8,487

Basic shares outstanding 34,026 33,542

Proven reserves per thousand shares 303 189
Proven plus probable reserves
per thousand shares 392 253


Find had an outstanding year in adding reserves on a per share basis. Proved reserves per share grew by 60 percent over 2004 and proved plus probable reserves were up by 55 percent.

Undeveloped Land

Undeveloped land is an important component of a Company's asset base as it represents future drilling opportunities. At December 31, 2005, Find owned 145,146 net acres of undeveloped land. The Company engaged Seaton-Jordan & Associates Ltd. ("Seaton-Jordan") to prepare an evaluation of the Company's undeveloped land holdings. Seaton-Jordan estimates their value to be approximately $19.1 million at March 14, 2006.

Reserve Life Index

Reserve life index is a measurement of the time remaining to produce out a company's reserves based on current production rates and the most recent independent evaluation of total remaining reserves.



Total Proved Total Proved plus
Reserves Probable Reserves
(Mboe) (Mboe)
----------------- ------------------
Total Company interest reserves
as at December 31, 2005 10,311 13,331

Annualized fourth quarter production 1,230 1,230

Reserve life index in years 8.4 10.8


Find's fourth quarter production volumes include only three days of its new production at Pembina West, yet the reserve volumes assigned by GLJ reflect the total reserves of the wells. If the reserve life index was calculated using the early January 2006 production rate of 5,100 boed, Find's proved reserve life index would be 5.5 years and its proved plus probable reserve life index would be 7.2 years.



Finding, Development and Acquisition Costs ($000)
For the Year Ended December 31, 2005

Excluding Including
Future Future
Capital Capital
----------------- ------------------

Total capital expenditures 96,111 96,111
----------------- ------------------

Change in estimated future capital
- total proved - 4,976
Change in estimated future capital
- total proved plus probable - 6,115

Total proved reserve additions (mboe) 7,320 7,320
Total proved plus probable
reserve additions (mboe) 8,882 8,882

Proved finding costs ($/boe) $13.13 $13.81
Proved plus probable finding costs ($/boe) $10.82 $11.51


The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.



Finding, Development and Acquisition Costs ($000)
For the Year Ended December 31, 2004
Excluding Including
Future Future
Capital Capital
----------------- ------------------

Total capital expenditures 45,720 45,720
----------------- ------------------

Change in estimated future capital
- total proved - 354
Change in estimated future capital
- total proved plus probable - 394

Total proved reserve additions (mboe) 2,482 2,482
Total proved plus probable
reserve additions (mboe) 3,179 3,179

Proved finding costs ($/boe) $18.42 $18.56
Proved plus probable finding costs ($/boe) $14.38 $14.51


Recycle Ratio

Recycle ratio is a measurement of a Company's ability to turn invested capital into cash flow, measured on a boe basis. The greater the recycle ratio, the greater the profit margin generated for shareholders through investing activities.



Cash flow from operations ($000) 37,589
Total production (Mboe) 1,185

Cash flow netback/boe 31.72
Proved plus probable finding costs/boe 10.82

Recycle ratio 2.9


During the fourth quarter, Find had a cash flow netback of $39.23 per boe. This would have resulted in a recycle ratio of 3.6.



Net Asset Value ($000)
As of December 31, 2005

Before Tax Before Tax Before Tax
Present Value Present Value Present Value
0% 5% 10%
------------- ------------- --------------

Total proved reserves 354,225 282,326 240,621
Total probable reserves 101,579 58,041 39,752
------------- ------------- --------------
Total value of reserves 455,804 340,367 280,373
Value of undeveloped land
as determined by
Seaton-Jordan &
Associates Ltd. 19,081 19,081 19,081
------------- ------------- --------------
Total asset value 474,884 359,447 299,455

Working capital deficiency 18,265 18,265 18,265
Bank debt 25,291 25,291 25,291
------------- ------------- --------------

Net asset value 431,328 315,891 255,899

Basic shares outstanding 34,026 34,026 34,026
------------- ------------- --------------

Net asset value per basic
share outstanding $12.68 $ 9.28 $ 7.52


Selected Supplemental Information ($000)

Dec. 31, Dec. 31, Dec. 31,
2005 2004 2003
------------- ------------- --------------
Petroleum and natural gas sales 63,931 34,681 8,931
Income (loss) for the year 11,963 2,905 (1,130)
Income (loss) per share - basic 0.36 0.10 (0.08)
Income (loss) per share - diluted 0.34 0.10 (0.08)
Total assets 171,865 116,054 79,269
Total current liabilities 60,509 31,966 26,787


2004 2004 2004 2004
Q4 Q3 Q2 Q1
----------- --------- ---------- ---------
Petroleum and natural
gas sales 10,029 8,814 9,805 7,705
Income (loss) for the quarter 960 1,398 877 (330)
Income (loss) per share
- basic and diluted 0.03 0.05 0.03 (0.01)


2005 2005 2005 2005
Q4 Q3 Q2 Q1
----------- --------- ---------- ---------
Petroleum and natural
gas sales 19,948 16,248 15,051 12,684
Income for the quarter 4,736 3,717 2,117 1,393
Income per share - basic 0.14 0.11 0.06 0.04
Income per share - diluted 0.13 0.11 0.06 0.04

Estimated Tax Pools ($000)
December 31,
2005
------------
Canadian oil and gas property expense -
Canadian development expense 41,393
Canadian exploration expense 13,620
Tangibles 34,365
Non-capital losses 7,794
Financing expenses 2,210
------------
99,382
------------
------------


Off-Balance Sheet Arrangements

Find currently does not have any off-balance sheet arrangements with any party, and does not expect to enter into any in the future.

Transactions with Related Parties

The Company has no transactions with any related parties.

Financial Instruments

From time to time, Find will enter into various hedge transactions to manage the cash flow of the Company and therefore to add certainty to capital programs. Products as diverse as swaps, costless collars, floor or ceilings may be employed, depending on the nature of the item being hedged and the economic environment existing at the time.

The Board of Directors has issued broad guidelines to management with regard to the quantity, timing, and term of proposed hedging transactions. At each regularly scheduled Board Meeting, current economic conditions as they relate to the main cash flow drivers of the Company are discussed. As well, outstanding current hedges and their future value are determined.

The Canadian Institute of Chartered Accountants (CICA) has issued a new accounting guideline on Hedging Relationships (AcG13), which was effective for 2004. This guideline, in addition to supplementing and interpreting existing hedging guidelines under GAAP, establishes certain other conditions required before hedge accounting may be applied. The primary drivers of Find's business that would be most likely to be hedged include oil and natural gas prices and the value of the CDN$. It is the opinion of management and the Company's auditors that hedge accounting is appropriate when the Company enters into transactions to add certainty to the price of oil and natural gas as it relates to future oil and gas production.

However, when Find enters into transactions to fix the price of the CDN$ relative to the US$, it is the opinion of management and the Company's auditors that these transactions should be recorded at their fair market value at each balance sheet date.

Critical Accounting Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect assets, liabilities, revenues and expenses. Management is also required to adopt accounting policies that require the use of significant estimates. Find's management believes the most critical accounting estimates that may have an impact on the Company's results are in the non-cash areas of accounting for property, plant and equipment, asset retirement obligations, and stock-based compensation.

Property, Plant and Equipment

Find follows the full cost method of accounting for oil and natural gas properties. Under this method, all costs related to the acquisition of, exploration for and development of oil and natural gas reserves are capitalized. These costs are then systematically charged to income through a depletion, depreciation and amortization (DD&A) calculation. This calculation is based on the unit of production method which amortizes the cost of oil and gas assets over the Company's proved oil and gas reserve base. Proved reserves are determined by the Company's independent reserve evaluation engineer using the guidelines of National Instrument 51-101. Changes to proved reserves in the future could increase or decrease the amount of the Company's DD&A.

The full cost accounting guidelines allow for the cost of unproved properties to be excluded from the DD&A calculation. For the year ended December 31, 2005, Find excluded $13.7 million from costs subject to DD&A. These costs are assessed quarterly for impairment. Should the judgment be made that these costs are impaired, an increase to DD&A will result.

Find is also required to perform a ceiling test calculation at least annually. Details of this calculation are contained in the notes to the financial statements and in this MD&A under the heading Financial Reporting and Regulatory Update. A steep decline in estimated future oil and gas prices could result in a reduction of the Company's proved reserves, or the cash flows attributable thereto, which could cause a write-off of a portion of its oil and gas properties.

Asset Retirement Obligations

Under the asset retirement obligations rules, the total fair value of the Company's retirement obligations are set up on the balance sheet at the discounted future value of the liability. The key areas of judgment are in determining the amount of the future liability, the appropriate discount rate and when the expenditures will be incurred. External factors influencing these obligations include commodity prices, interest rates and changes to regulatory requirements. Dramatic changes in any of these could result in an increase or decrease in net income.

Stock-based Compensation

Find is required to calculate the fair value of stock options at the time of grant and charge this to income in a systematic manner over the vesting period of the options. The calculation method that Find has adopted to calculate the fair value of options is the Black-Scholes model. The most critical estimate in the Black-Scholes model is the expected volatility of Find's shares. Management has determined that 45 - 50 percent is an appropriate volatility rate for Find. Actual volatility could be more or less than 50 percent which could have a material impact on net income.

Share Capital

As at March 22, 2006, the Corporation has 34,230,783 shares and 3,248,500 stock options outstanding.

Disclosure Controls and Procedures

Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Company is accumulated and communicated to the Company's management as appropriate to allow timely decisions regarding required disclosure. The Company's Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation as of the end of the period covered by the 2005 annual filings, that the Company's disclosure controls and procedures are effective to provide reasonable assurance that material information related to the Company, including its consolidated subsidiaries, is made known to them by others within those entities. It should be noted that while the Company's Chief Executive Officer and Chief Financial Officer believe that the Company's disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the disclosure controls and procedures or internal controls over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Business Risks

Find Energy is subject to business risks that impact the market in general and the oil and gas business in particular. These include, but are not limited to the following:

Market Risks

The primary risk factor impacting Find's future performance is the price of oil and gas followed by currency fluctuations and interest rates. In addition, Find is impacted by the current industry demand for oilfield services which has driven up costs. Cash flow, as impacted by these risks has a direct impact on Find financing capital programs.

The Corporation has a hedging policy such that it can enter into commodity and currency hedges when it deems it appropriate. No hedges are currently in place.

Sensitivities

A critical component in Find's growth plan is the Company's cash flow. Cash flow represents funds available for reinvestment in capital projects. Among the various components that affect cash flow, management has determined that the price of oil and natural gas has the most impact on the Company's cash flow. Of course, adding production volumes at the lowest possible cost also has a very meaningful impact on available cash flow. The CDN dollar exchange rate is the next most influential, while changes in interest rates have very little impact. The following table illustrates the sensitivity of Find's cash flow to changes in natural gas prices, oil prices and the CDN dollar.



Annual Cash Flow Cash Flow
($000) per Share
----------------- ------------------
100 boed of production 1,464 $ 0.04
Crude oil - WTI price change
of US$1.00/bbl 496 $ 0.01
Natural gas - AECO price change
of $0.25/mcf 1,592 $ 0.05
CDN$ - change of US$0.01 358 $ 0.01


Operational, Environmental and Safety Risks

The Company is subject to environmental laws and regulatory initiatives which may impose restrictions in areas that Find operates or requires Find to incur additional costs to ensure compliance.

Find is also subject to the occurrence of unexpected events such as fires, blowouts and equipment failures associated with the production of oil and gas. The Company has a comprehensive insurance program in place to mitigate losses associated with such events.


Consolidated Financial Statements of

FIND ENERGY LTD.

December 31, 2005



FIND ENERGY LTD.
Consolidated Balance Sheets
December 31, 2005 and December 31, 2004
----------------------------
----------------------------
December 31, December 31,
2005 2004
----------------------------
$ $
----------------------------
ASSETS

CURRENT
Cash and cash equivalents 10,630 200
Accounts receivable 16,662,073 11,528,233
Note receivable (Note 3) - 2,212,500
Prepaid expenses 279,892 196,374
Foreign exchange contracts (Note 11(a)) - 372,060
----------------------------
16,952,595 14,309,367

Deposits and other (Note 4) 350,103 230,761
Property and equipment (Note 5) 154,562,049 101,514,146
----------------------------
171,864,747 116,054,274
----------------------------
----------------------------

LIABILITIES

CURRENT
Accounts payable and accrued liabilities 35,128,189 22,785,505
Income taxes payable 89,118 26,400
Bank indebtedness (Note 7) 25,291,229 9,153,618
----------------------------
60,508,536 31,965,523
----------------------------
Asset retirement obligations (Note 6) 4,132,695 3,263,675
----------------------------
Future income taxes (Note 8) 13,915,160 5,958,016
----------------------------

SHAREHOLDERS' EQUITY

Share capital (Note 9) 79,167,670 72,076,343
Contributed surplus 2,793,172 1,343,471
Retained earnings 11,347,514 1,447,246
----------------------------
93,308,356 74,867,060
----------------------------
171,864,747 116,054,274
----------------------------
----------------------------

Commitments and contingencies (Note 11)
The accompanying notes are an integral part of these financial
statements.

Approved by the Board


Robert Cook Richard A.N. Bonnycastle
Director Director


FIND ENERGY LTD.
Consolidated Statements of Operations and Retained Earnings
For the year ended December 31

-----------------------------------------------
Three Months Ended Year Ended
December 31 December 31
-----------------------------------------------
2005 2004 2005 2004
(unaudited) (unaudited)
-----------------------------------------------
$ $ $ $
-----------------------------------------------
REVENUE
Petroleum and
natural gas sales 19,947,595 9,354,625 63,462,949 34,680,900
Royalties 4,971,515 2,238,455 15,158,623 7,772,002
-----------------------------------------------
14,976,080 7,116,170 48,304,326 26,908,898
Interest and other 506 5,075 100,506 102,459
Realized gain/(loss)
on financial
instruments
(Note 11(a)) - 321,457 (67,685) 349,357
Unrealized gain on
financial instruments - 372,060 - 372,060
-----------------------------------------------
14,976,586 7,814,762 48,337,147 27,732,774
-----------------------------------------------
EXPENSES
Operating 2,444,332 2,210,985 9,201,651 8,367,832
General and
administrative 163,879 197,564 952,040 1,676,083
Interest 64,661 102,613 418,311 641,953
Depletion,
depreciation and
accretion 4,229,376 3,425,819 16,395,965 11,254,030
Stock-based
compensation
(Note 9(f)) 267,667 240,545 973,576 752,935
-----------------------------------------------
7,169,915 6,177,526 27,941,543 22,692,833
-----------------------------------------------
Income before taxes 7,806,671 1,637,236 20,395,604 5,039,941
-----------------------------------------------

Provision for taxes
(Note 8)
Capital 141,292 103,191 548,097 576,416
Future 2,929,560 574,408 7,884,978 1,558,744
-----------------------------------------------
3,070,852 677,599 8,433,075 2,135,160
-----------------------------------------------
Income for the period 4,735,819 959,637 11,962,529 2,904,781
Retained earnings/
(deficit), beginning
of the period 6,611,695 487,609 1,447,246 (1,457,535)
Excess of cost of
shares acquired over
stated value
(Note 9(d)) - - (2,062,261) -
-----------------------------------------------
Retained earnings,
end of period 11,347,514 1,447,246 11,347,514 1,447,246
-----------------------------------------------
Income per share
Basic 0.14 0.03 0.36 0.10
-----------------------------------------------
Diluted 0.13 0.03 0.34 0.10
-----------------------------------------------
Weighted average
number of shares
- basic (Note 10) 33,909,504 31,714,740 33,627,479 28,530,685
-----------------------------------------------
Total number of shares
outstanding, end of
period (Note 9(b)) 34,026,283 33,542,110 34,026,283 33,542,110
-----------------------------------------------
-----------------------------------------------

The accompanying notes are an integral part of these financial
statements.


FIND ENERGY LTD.
Consolidated Statements of Cash Flows
For the year ended December 31

-----------------------------------------------
Three Months Ended Year Ended
December 31 December 31
-----------------------------------------------
2005 2004 2005 2004
(unaudited) (unaudited)
-----------------------------------------------
$ $ $ $
-----------------------------------------------
CASH FLOWS RELATED TO
THE FOLLOWING
ACTIVITIES:

OPERATING

Income for the period 4,735,819 959,637 11,962,529 2,904,781
Adjustments for:
Unrealized gain
on financial
instruments
(Note 11(a)) - (372,060) 372,060 (372,060)
Depletion,
depreciation
and accretion 4,229,376 3,425,819 16,395,965 11,254,030
Stock-based
compensation 267,667 240,545 973,576 752,935
Future income taxes 2,929,560 574,408 7,884,978 1,558,744
-----------------------------------------------
12,162,422 4,828,349 37,589,108 16,098,430
Changes in non-cash
working capital (1,450,006) (176,123) (127,779) (1,236,002)
-----------------------------------------------
10,712,416 4,652,226 37,461,329 14,862,428
-----------------------------------------------
FINANCING

Issue of shares,
net of share
issue costs (3,050) 15,132,073 7,259,236 26,377,551
Bank indebtedness 24,022,935 (7,877,178) 16,137,611 (5,450,260)
Redemption of share
capital - normal
course issuer bid
(Note 9(d)) - - (3,591,226) -
Changes in non-cash
working capital - - (178,665) -
-----------------------------------------------
24,019,885 7,254,895 19,626,956 20,927,291
-----------------------------------------------
INVESTING

Property and
equipment (41,184,661)(18,853,074)(95,173,168)(43,623,885)
Other deposits (2,792) - (119,342) (6,850)
Proceeds on sale
of properties - - 28,507,666 -
Changes in non-cash
working capital 6,465,582 6,945,953 9,706,989 7,817,838
-----------------------------------------------
(34,721,871)(11,907,121)(57,077,855)(35,812,897)
-----------------------------------------------
Net increase/(decrease)
in cash and cash
equivalents 10,430 - 10,430 (23,178)
Cash and cash
equivalents,
beginning of period 200 200 200 23,378
-----------------------------------------------
Cash and cash
equivalents,
end of period 10,630 200 10,630 200
-----------------------------------------------
Taxes paid during
the period 108,400 586,479 578,718 1,023,783
-----------------------------------------------
Interest paid
during the period 53,042 30,293 361,001 527,939
-----------------------------------------------

The following non-cash transaction has been excluded from the statement
of cash flows:
The acquisition of
petroleum and natural
gas properties by the
issuance of share
capital (Note 9(b)) 1,100,000 - 1,100,000 -
-----------------------------------------------
-----------------------------------------------

The accompanying notes are an integral part of these financial
statements.


FIND ENERGY LTD.

Notes to the Consolidated Financial Statements

December 31, 2005 and 2004

1. BUSINESS OF THE CORPORATION

The Corporation's business is the exploration for and the development of petroleum and natural gas properties in Canada.

2. SIGNIFICANT ACCOUNTING POLICIES

These consolidated financial statements of Find Energy Ltd. (the "Corporation") have been prepared by management in accordance with accounting principles generally accepted in Canada. The preparation requires management to make estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. Actual results would differ from these estimates.

Consolidation

The consolidated financial statements include the accounts of the Corporation and its wholly owned subsidiary companies.

A significant part of the Corporation's exploration, development and production activities are conducted jointly with others, and these financial statements reflect only the Corporation's proportionate interest in such activities.

Revenue recognition

Petroleum and natural gas revenue is recognized at the time sales volumes are delivered to the purchasers. The Corporation does not recognize inventory related to volumes produced but not sold at the end of the year.

Petroleum and natural gas operations

The Corporation follows the full cost method of accounting whereby all costs relating to the acquisition, exploration, and development of petroleum and natural gas reserves are capitalized.

Capitalized costs of petroleum and natural gas properties and related equipment are depleted and depreciated using the unit-of-production method based on estimated gross proved developed and undeveloped petroleum and natural gas reserves as determined by independent consulting engineers. For the purpose of this calculation, production and reserves of petroleum and natural gas are converted to equivalent units based on the relative energy content of six thousand cubic feet of natural gas to one barrel of oil. Costs of acquiring and evaluating unproved properties are excluded from costs subject to depletion and depreciation until it is determined that proved reserves are attributable to the properties or impairment occurs. Gains or losses on sales of properties are recognized only when crediting the proceeds to cost would result in a change of 20% or more in the depletion and depreciation rate.

Impairment

The Corporation places a limit on the total carrying value of property and equipment that is depleted against future revenues.

Impairment is recognized if the carrying value of petroleum and natural gas properties less accumulated depletion and depreciation, related asset retirement obligations and the lesser of cost and fair value of unproved properties exceeds the estimated future cash flows expected to result from the Corporation's proved reserves. Cash flows are calculated on an undiscounted basis using forecast prices and costs.

If impairment occurs, the Corporation will measure the amount by comparing the carrying value of the property and equipment to the estimated net present value of future cash flows from the proved and probable reserves. Cash flows are discounted at the Corporation's risk free rate. The excess of the carrying value less the net present value of future cash flows would be recorded as additional depletion expense. The cost of unproved properties is excluded from the ceiling test calculation and is subjected to a separate impairment test.

Asset retirement obligations

The Corporation recognizes the estimated fair value of an asset retirement obligation in the period a well or related asset is drilled, constructed or acquired. The fair value of the estimated obligation is estimated using the present value of the estimated future cash outflows to abandon the asset, calculated at the Corporation's credit-adjusted risk-free interest rate. The fair value is recorded as a long-term liability with a corresponding increase in the carrying amount of the related asset. The liability is increased each reporting period with the accretion being charged to income until the property is depleted or sold. The capitalized amount is depleted on a unit-of-production basis over the life of the reserves. Actual abandonment and restoration costs incurred are charged against the asset retirement obligation.

The Corporation reviews the obligation regularly such that revisions to the estimated timing of cash flows, discount rates and estimated costs will result in an increase or decrease to the asset retirement obligation.

Stock-based compensation

The Corporation issues stock options to directors, officers, employees and other consultants. Compensation cost attributable to stock options is measured at fair value at the date of grant and expensed over the vesting period with a corresponding increase in contributed surplus. When stock options are exercised, the cash proceeds along with the amount previously recorded as contributed surplus is recorded as share capital. The Corporation does not incorporate an estimated forfeiture rate for stock options that will not vest, but accounts for forfeitures as they occur.

Measurement uncertainty

The amounts recorded for depletion and depreciation of property and equipment, the ceiling test calculation and the provision for asset retirement obligations are based on estimates of proved and probable petroleum and natural gas reserves, production rates, petroleum and natural gas prices, future costs and other relevant assumptions. The Corporation's reserve estimates are evaluated annually by an independent engineering firm. The amounts disclosed relating to the fair value of stock options issued and the resulting income effect (Note 9(f)) are based on estimates of the future volatility of the Corporation's share price, expected lives of the options, expected dividends and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be material.

Furniture and equipment

Furniture and equipment are recorded at cost and are being depreciated on a declining balance basis at rates of 20% to 30% per year.

Cash and cash equivalents

Cash and cash equivalents are comprised of deposits with banks and short-term investments with an initial term of less than 90 days.

Income taxes

The Corporation follows the liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributed to differences between the amounts reported in the financial statements and their respective tax bases, using substantively enacted income tax rates. The effect of a change in income tax rates on future income tax liabilities and assets is recognized in income in the period that the change occurs.

Flow-through shares

The resource expenditure deductions for income tax purposes related to exploratory and development activities funded by flow-through share arrangements are renounced to investors in accordance with tax legislation. Share capital is reduced and future income taxes are increased by the foregone tax benefits related to the renounced tax deduction on the date of renunciation.

Income (loss) per share

Income (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the year. Diluted per share amounts reflect the potential dilution that could occur if "in the money" options to purchase common shares were exercised. The treasury stock method is used to determine the dilutive effect of stock options, whereby proceeds from the exercise of "in the money" stock options and share purchase warrants, plus the unamortized portion of stock-based compensation, are assumed to be used to purchase common shares at the average market price of the shares during the year.

Financial instruments

The Corporation holds various forms of financial instruments. The estimated fair value of recognized financial instruments has been determined based on the Corporation's assessment of available market information and appropriate valuation methodologies; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a future market transaction. The fair values of these financial instruments approximate their carrying amounts except for the commodity marketing arrangements as disclosed in Note 11(a).

(a) Credit risk

The majority of the Corporation's accounts receivable is due from joint venture partners in the oil and gas industry and from purchasers of the Corporation's oil and natural gas production. The Corporation generally extends unsecured credit to these customers and therefore, the collection of accounts receivable may be affected by changes in economic or other conditions. Management believes the risk is mitigated by the size and reputation of the companies to which they extend credit. The Corporation has not experienced any credit loss in the collection of accounts receivable to date.

(b) Commodity price risk

The Corporation enters into forward fixed-price commodity contracts, physical contracts and swap or collar agreements to hedge its exposure to the risks associated with fluctuating petroleum and natural gas prices. The Corporation also uses forward currency contracts to reduce its month-to-month exposure to exchange rate fluctuations in petroleum and natural gas prices.

Effective January 1, 2004, the Corporation adopted the new Canadian Institute of Chartered Accountants ("CICA") Accounting Guideline 13 "Hedging Relationships" ("AcG-13"), which deals with the identification, designation, documentation and effectiveness of hedging relationships for the purpose of applying hedge accounting. Hedge accounting is used when there is a high degree of correlation between price movements in the derivative instrument and the item designated as being hedged. Gains and losses associated with risk management activities that meet hedge accounting criteria are recorded as adjustments to the production revenue at the time the related production is sold. If correlation ceases, hedge accounting is terminated and future changes in the market value of the derivative instruments are recognized as gains or losses in the period of change. Financial instruments that are not designated as hedges under the guideline are recorded on the balance sheet as either an asset or liability with the change in fair value recognized in net earnings.

The Corporation has elected to apply hedge accounting for all of its commodity price risk contracts. The forward fixed price commodity contracts, physical contracts and swap or collar agreements are initiated within the guidelines of the Corporation's risk management policy. The Corporation identifies all relationships between the hedging instruments and hedged production, as well as its risk management objective and strategy for undertaking various risk management transactions. The Corporation formally documents its risk management objectives and strategies, including the permitted use of derivative financial instruments. The Corporation believes the forward fixed price commodity contracts, physical contracts and swap agreements are effective as hedges, both at inception and over the term of the instrument. As a result, the fair values of these derivative instruments are not reflected in the financial statements. All transactions of this nature entered into by the Corporation are related to future petroleum and natural gas production.


See Note 11 for additional information regarding financial instruments and risk management.

(c) Foreign currency exchange risk

The Corporation is exposed to foreign currency fluctuations as crude oil and natural gas prices received are referenced to U.S. dollar-denominated prices. The Corporation may enter into foreign exchange forward contracts to mitigate risk.

The Corporation has elected not to designate any of its forward currency contracts as accounting hedges under AcG-13, and accordingly has marked-to-market these financial instruments.

(d) Interest rate risk

The Corporation's borrowings are subject to floating interest rates. The interest rates fluctuate with changes in market rates.

3. NOTE RECEIVABLE

On October 1, 2004 the Corporation sold certain Saskatchewan properties. Proceeds received include a promissory note. As at September 30, 2005 the note was paid in full.

4. DEPOSITS AND OTHER

Deposits and other is comprised of deposits required under Crown royalty regulations and operating lease obligations.



5. PROPERTY AND EQUIPMENT
Accumulated Net Book
Depletion Value
and December 31
Cost Depreciation 2005
------------ ------------- ------------
$ $ $
------------ ------------- ------------
Petroleum and natural gas
properties and equipment 185,130,884 30,621,649 154,509,235
Furniture and equipment 115,515 62,701 52,814
------------ ------------- ------------
185,246,399 30,684,350 154,562,049
------------ ------------- ------------
------------ ------------- ------------


Unproved properties and proprietary seismic data of $13,712,600 have been excluded from costs subject to depletion. During 2005, the Corporation capitalized $2,484,100 of general and administrative expenditures related to exploration and development activities.


Accumulated Net Book
Depletion Value
and December 31
Cost Depreciation 2004
------------ ------------- ------------
$ $ $
------------ ------------- ------------

Petroleum and natural gas
properties and equipment 115,918,850 14,447,371 101,471,479
Furniture and equipment 83,544 40,877 42,667
------------ ------------- ------------
116,002,394 14,488,248 101,514,146
------------ ------------- ------------
------------ ------------- ------------


Unproved properties and proprietary seismic data of $13,305,300 have been excluded from costs subject to depletion. During 2004, the Corporation capitalized $1,563,700 of general and administrative expenditures related to exploration and development activities.

The benchmark and Corporation prices used for the December 31, 2005 ceiling test are as follows:



Oil Natural Gas
------------------------ ----------------------
Benchmark Benchmark
Edm. Light Corporation AECO Spot Corporation
($/bbl) ($/bbl) ($/mcf) ($/mcf)
------------------------ ----------------------

2006 66.25 54.62 10.60 11.17
2007 64.00 52.47 9.25 9.73
2008 59.25 48.09 8.00 8.38
2009 55.75 44.78 7.50 7.85
2010 54.00 43.23 7.20 7.51


Prices remain constant between 2011 and 2012 and increase at a rate of approximately 2.0 % per year for natural gas and oil after 2012. Adjustments were made to the benchmark prices for purposes of the ceiling test, to reflect varied delivery points and quality differentials in the products delivered.

6. ASSET RETIREMENT OBLIGATIONS

The effect of the change in asset retirement policy for the years ended December 31, 2004 and December 31, 2005 are as follows:



Year Ended Year Ended
December 31 December 31
2005 2004
----------------- -----------------
$ $
----------------- -----------------

Asset retirement
obligations, beginning of year 3,263,675 3,616,855
Liabilities incurred 1,198,054 481,500
Liabilities acquired 25,500 -
Liabilities settled (554,397) (1,070,067)
Accretion expense 199,863 235,387
Revisions in estimated
cash flows - -
----------------- -----------------
Asset retirement
obligations, end of year 4,132,695 3,263,675
----------------- -----------------
----------------- -----------------


The total estimated, undiscounted cash flows required to settle the obligations at December 31, without including salvage, is $8,523,200 (2004 - $6,131,460). These amounts have been discounted using a credit-adjusted risk-free rate of 7.0%. The Corporation expects these obligations to be settled, on average in 10.1 years, the majority of which is expected to be incurred between 2009 and 2024.

7. BANK INDEBTEDNESS

Effective December 20, 2005, the Corporation agreed to a revised credit facility comprised of a $65 million Revolving Operating Demand Loan by way of prime rate loans, guaranteed notes and letters of credit. The credit facility bears interest as follows:

- Prime-based loans - Interest is payable in Canadian dollars at Prime plus 0.0% per 365-day period;

- Guaranteed Notes - Fee is payable in Canadian dollars at base rate plus 1.25% per 365-day period.

The facility is subject to a review on or before April 30, 2006.

The facility is secured by a general security agreement providing a security interest over all present and after acquired personal property and a floating charge on all lands.

The balance as of December 31, 2005 is comprised of the following:



Revolving operating demand
loan at prime plus 0% $ 24,516,930
Bankers Acceptance -
Letter of Guarantee 774,299
-----------------
$ 25,291,229
-----------------
-----------------


The Letter of Guarantee has been issued to the Monitor appointed under the Company's Creditor Arrangement Act for Liberty Oil & Gas Ltd., a former subsidiary of Lexxor Energy Inc. ("Lexxor"). Lexxor was acquired by the Corporation in 2003. The Monitor is currently settling creditor claims and the Letter of Guarantee is periodically reduced as the claims are settled by the Corporation.

8. INCOME TAXES

The provision for capital taxes reflected in the consolidated statement of operations includes Large Corporation and Saskatchewan Capital taxes and Saskatchewan Resource Surcharge.

Future income tax expense differs from that which would be expected from applying the combined effective Canadian federal and provincial tax rate of 37.62% (2004 - 38.62%) to income before income taxes as follows:



2005 2004
$ $
----------------- -----------------

Expected income tax 7,672,826 1,946,425
Adjustment resulting from:
Tax rate adjustment (911,674) (264,278)
Non-deductible Crown charges, net 3,298,171 1,730,653
Resource allowance (2,690,484) (1,383,730)
Alberta Royalty Tax Credit (103,614) (143,613)
Non-deductible stock-based
compensation 556,200 414,402
Unrealized gain on financial
instrument - (143,690)
Other 63,553 (87,375)
Recovery not previously
recognized - (510,050)
----------------- -----------------
Future income tax 7,884,978 1,558,744
----------------- -----------------
----------------- -----------------

The components of the future income tax liability (asset) are as
follows:

2005 2004
$ $
----------------- -----------------

Temporary differences related
to property and equipment and
asset retirement obligations 18,157,578 10,157,532
Loss carry forwards (2,671,561) (2,481,995)
Share issue costs and financing
fees (747,735) (905,879)
Attributed royalty income
deduction carry forward (823,122) (811,642)
----------------- -----------------
13,915,160 5,958,016
----------------- -----------------
----------------- -----------------

The Corporation has the following non-capital loss carry forwards:

Year of
Expiry Amount
----------------- -----------------
2007 $ 62,826
2008 6,811,804
2009 919,021
-----------------
$ 7,793,651
-----------------
-----------------


9. SHARE CAPITAL

(a) Authorized

Unlimited number of Common Shares
Unlimited number of Preferred Shares, issuable in series


2005 2004
----------------------- ------------------------
(b) Issued common Number of Amount Number of Amount
shares Shares $ Shares $
-------------------------------------------------

Balance January 1 33,542,110 72,076,343 25,941,163 50,098,065
Issued under Stock
Option Plan 66,666 263,997 - -
Shares repurchased
(Note 9(d)) (710,400) (1,528,964) - -
Issued for cash on
exercise of warrants - - 947 5,682
Issued for cash
pursuant to private
placements (Note 9(C)) 1,000,000 7,600,000 7,600,000 28,065,000
Issued for acquisition
of properties 127,907 1,100,000 - -
Future income taxes
on expenditures
renounced for
flow-through shares - - - (4,972,058)
-------------------------------------------------
34,026,283 79,511,376 33,542,110 73,196,689
Share issue costs,
(net of tax of
$175,723, 2004 -
$572,786) - (343,706) - (1,120,346)
-------------------------------------------------
Balance, end of year 34,026,283 79,167,670 33,542,110 72,076,343
-------------------------------------------------
-------------------------------------------------


(c) On June 3, 2004, the Corporation completed a private placement of 3,500,000 flow- through common shares at a price of $3.45 per share for gross proceeds of $12,075,000. Transaction costs were $788,000 including fees paid to underwriters.

In accordance with the terms of the offering and pursuant to certain provisions of the Income Tax Act (Canada), the Corporation renounced, for income tax purposes, exploration expenditures of $12,075,000 to the holders of the flow-through common shares effective December 31, 2004. The Corporation incurred $8,574,100 of expenditures to December 31, 2004, with the remaining $3,500,900 expended in 2005. Future income tax cost of $4,085,000 associated with renouncing the expenditures was recorded at December 31, 2004.

On November 10, 2004, the Corporation completed a private placement of 4,100,000 common shares at a price of $3.90 per share for gross proceeds of $15,990,000. Transaction costs were $858,000 including fees paid to underwriters.

On August 18, 2005, the Corporation completed a private placement of 1,000,000 flow-through common shares at a price of $7.60. Transaction costs were $517,000 including fees paid to underwriters. In accordance with the terms of the offering and pursuant to certain provisions of the Income Tax Act (Canada), the Corporation renounced, for income tax purposes, exploration expenditures of $7,600,000 to the holders of the flow-through common shares effective December 31, 2005, all of which had been incurred by December 31, 2005. Future tax cost of $2,571,080 associated with renouncing the expenditures will be recorded on the date of renunciation in the first quarter of 2006.

(d) On June 2, 2005, the Corporation announced a normal course issuer bid that will allow purchase and cancellation of up to 2,422,346 common shares. This normal course issuer bid is scheduled to expire on June 1, 2006. A total of 710,400 common shares were purchased during the year at a cost of $3,591,225. The excess of the cost to repurchase over the stated value of the shares of $2,062,261 was charged to retained earnings.

(e) Common share purchase warrants

During 2004, the Corporation had warrants outstanding entitling the holders to purchase 494,301 common shares at $6.00 per share. Of these, 947 warrants were exercised and converted to common shares. The remaining warrants expired unexercised on July 23, 2004.

(f) Stock option plan

On September 10, 2003, the shareholders approved a stock option plan (the "Plan") for the Corporation. The Plan authorizes the Board to grant stock options to directors, officers, employees and consultants of the Corporation. The Plan also provides for options to be granted at the defined market price, and that the term of the option must be no more than five years. Stock options issued vest over a three-year period commencing on the first anniversary of, and expire five years after the date of issue.

A summary of the Corporation's stock option plan for the years ended December 31, 2005 and December 31, 2004, is as follows:



2005 2004
----------------------- ------------------------
Weighted Weighted
Number Average Number Average
Continuity of of Exercise of Exercise
stock options Shares Price Shares Price
---------- ---------- ---------- ----------
Outstanding,
December 31 3,259,000 $2.81 2,140,000 $2.65
Granted during
the period 332,500 3.64 1,371,500 3.04
Exercised during
the period (66,666) 2.68 - -
Cancelled during
the period (134,834) 2.88 (252,500) 2.65
---------- ---------- ---------- ----------
Outstanding,
December 31 3,390,000 $2.89 3,259,000 $2.81
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------

The following table summarizes information about the Corporation's stock
options outstanding and exercisable at December 31, 2005:

Options Outstanding Exercisable Options
---------------------------------- ----------------------
Weighted
Average
Remaining Weighted Weighted
Contractual Average Average
Number Life Exercise Number Exercise
Outstanding (Years) Price Exercisable Price
---------------------------------- ----------------------

$2.30 to $2.80 2,521,600 3.0 $2.66 1,444,699 $2.65
$2.81 to $3.30 353,000 4.1 3.02 31,833 2.90
$3.31 to $3.80 440,400 3.9 3.66 146,800 3.66
$3.81 to $4.30 15,000 4.5 4.20 - -
$5.51 to $6.00 60,000 4.6 6.00 - -
---------------------------------- ----------------------
3,390,000 3.2 $2.89 1,623,332 $2.75
---------------------------------- ----------------------
---------------------------------- ----------------------


Compensation expense recognized for the year ended December 31, 2005 related to options granted in prior years was $1,381,873, of which $894,060 was charged to income and $487,813 was capitalized to property and equipment.

The fair value of stock options granted during the year ended December 31, 2005 was estimated using the Black-Scholes option pricing model and with the following assumptions: expected volatility (45% to 50%); risk-free interest rates (3.195% to 3.895%); expected life (5 years); and expected future dividends (nil). Stock options granted during the period had an estimated fair value of $1.34 to $2.63 per share with an average fair value of $1.67.

Compensation expense recognized for the year ended December 31, 2005 related to options granted in 2005 was $153,160, of which $79,516 was charged to income and $73,644 was capitalized to property and equipment.

Compensation cost recognized for the year ended December 31, 2004 related to options granted in prior years was $792,003, of which $528,739 was charged to general and administration expense and $263,264 was capitalized to property and equipment.

The fair value of stock options granted during the year ended December 31, 2004 was estimated using the Black-Scholes option pricing model and with the following assumptions: expected volatility (50%); risk-free interest rates (3.24% to 4.07%); expected life (5 years); and expected future dividends (nil). Stock options granted during the period had an estimated fair value of $1.23 to $1.77 per share with an average fair value of $1.45.

Compensation cost recognized for the year ended December 31, 2004 related to options granted in 2004 was $326,345, of which $224,196 was charged to general and administrative expense and $102,149 was capitalized to property and equipment.

10. WEIGHTED AVERAGE SHARES OUTSTANDING

The weighted average number of common shares issued and outstanding for the three months and year ended December 31, 2005 and December 31, 2004 are as follows:



Three months ended
December 31 Year ended
(unaudited) December 31
----------------------- ------------------------
2005 2004 2005 2004
----------------------- ------------------------
Basic 33,909,504 31,714,740 33,627,479 28,530,685

Diluted 35,389,228 32,088,489 35,107,203 28,904,434


11. COMMITMENTS AND CONTINGENCIES

(a) Commodity marketing arrangement and foreign exchange contracts

The Corporation has a price risk management program whereby the commodity price associated with a portion of its future production is fixed. The forward and futures contracts are subject to market risk from fluctuating commodity prices and exchange rates, however, gains and losses on the contracts are offset by changes in the value of the Corporation's production and recognized in income in the same period and category as the hedged item. The Corporation also enters into foreign exchange contracts to manage foreign currency fluctuations.

As at December 31, 2005, the Corporation has no outstanding commodity marketing arrangements or foreign exchange contracts. The gain on settlement of foreign exchange contracts during the year was $304,375. At December 31, 2004, $372,060 of this was marked-to-market, with a net realized loss in of 2005 of $67,685.

(b) Operating commitments

In order to ensure continued availability of, and access to, facilities and services to meet its operational requirements, the Corporation has entered into operating leases for office space and other property and equipment. Under contracts existing at December 31, 2005, future minimum amounts payable on a fiscal year basis, excluding operating costs, are as follows:



2006 221,684
2007 54,082
2008 8,594
2009 7,584
2010 1,896
----------

293,840
----------
----------


(c) Dispute with industry partner

On August 8, 2003, a joint-venture partner of the Corporation filed a statement of claim in the amount of $768,000 in respect of a dispute regarding working interest participation. A statement of defense has been filed and management believes the claim is unlikely to succeed.

12. SUBSEQUENT EVENT

Subsequent to year-end, the Corporation increased its line of credit to a $100 million Revolving Demand Loan. The facility is subject to a review on or before September 30, 2006.

Contact Information

  • Find Energy Ltd.
    William T. Davis
    CEO
    (403) 232-4802
    (403) 232-4824 (FAX)
    or
    Find Energy Ltd.
    Jeffrey P. Jongmans
    CFO
    (403) 232-4809
    (403) 232-4824 (FAX)
    Website: www.findenergy.ca